Program priorities, at-a-glance

• Briefly, what are the top two outcomes your team must achieve on this drilling program?
• Which of these outcomes are highest priority for you on this program Options: Meet AFE schedule, Reduce days per well, Lower cost per well, Top-quartile TRIR, Minimize NPT, Flexible pad walking
• What timeline constraints drive your spud-by dates and pad sequencing?
• How many wells per pad and average target drilling days per well are you planning?
• Who in your organization will have final approval over rig selection and the mobilization schedule? Options: Drilling manager, VP operations, Supply chain/procurement, Joint venture operator, Other
• What single timing or scope constraint, if unmet, would cause you to delay awarding a rig contract?

Where schedules and outcomes are slipping

• When recent wells missed AFE or schedule, what happened and who inside your organization felt the impact first?
• Walk me through the most recent non-productive time event on an offset well, what caused it, and how long it took to recover
• How often do NPT events longer than 8 hours occur on your pads today? Options: Multiple times per month, Monthly, Quarterly, Rarely, Unknown
• Which equipment or operational failures have driven the largest schedule overruns on your recent wells Options: Rig mechanical (top drive, drawworks), Connection time inefficiencies, Poor walking capability, Crew performance variability, Mud or hole stability issues, Other
• If you could eliminate one recurring cause of delay on your pads, which would accelerate internal approvals most?

Who else could you go with and why that matters

• Who are the incumbents, alternative contractors, or internal options you are actively considering, and why might you stick with them?
• Which of these alternatives are you actively evaluating right now Options: Incumbent contractor, Company-owned rigs, Short-term rental rigs, Lower-spec rigs to meet schedule, Other external vendors, No alternative yet
• If you stayed with the current approach, what would have to be true about its cost or performance for you to avoid changing vendors this cycle?
• Has anyone on your team proposed solving mobilization or performance gaps internally rather than using an outside contractor? If so, what was proposed and by whom
• What single criterion would definitively make you switch away from the incumbent this cycle

Does the rig match the ground truth at the site

• What rig specification mismatch would make you reject a supplier outright during technical review
• Which of these hole and casing program constraints must the rig support without modification Options: Maximum hookload and torque, Top drive capacity and continuous rotation, Mud system and solids control, BOP stack and H2S rating, Walking capacity and pad footprint
• Describe any access, pad size, or crane limitations on site that will affect mobilization or rig layout
• Do you require the rig to walk between laterals on a pad or to walk full pads between locations Options: Walk between wells on the same pad, Walk between pads, No walking required, Depends on pad
• What single technical showstopper at the site would make mobilization impossible for a given rig

Who keeps people safe and rigs running

• If a crew change produced a persistent drop in drilling performance, what would you expect a contractor to do first to restore performance
• How do you measure crew quality across shifts and what thresholds trigger formal corrective action
• Which safety KPIs matter most to your leadership Options: TRIR, Near misses, Lost-time incidents, Stop-work orders, Near-well control events
• Tell me about a recent safety event that led to operational or procedural changes, what changed, and who owned the new process
• What safety metric gap would cause you to pause or stop operations with a contractor immediately

Money talks, and deal breakers

• What commercial term would make you rule out a dayrate-based contract before negotiations begin
• Which pricing structure do you prefer for this program Options: Dayrate, Footage-based, Performance-linked with bonuses and penalties, Hybrid structure, Undecided
• How is your capital approval process tied to AFE timelines and what lead time do you need between contract signature and mobilization
• Which contractual provisions are non-negotiable for your team Options: Minimum rig technical spec, Safety KPIs and penalties, Insurance and indemnity levels, Mobilization window and penalties, Termination for convenience
• If a contractor met your safety and technical requirements but their dayrate exceeded budget by 10 percent, which would you be most likely to do Options: Re-negotiate scope, Accept higher dayrate and proceed, Delay contracting to seek alternatives, Select a different vendor, Consider internal option

Operational readiness and the gates that matter

• Which regulatory, landowner, or road permit constraint on your sites could delay rig mobilization beyond your target window
• Which of these prerequisites are already cleared for the first spud Options: Permits and surface use agreements, Pad grading and access roads complete, Water sourcing and disposal permits, Power and fuel logistics arranged, None of the above
• Who in your organization owns each of these gates and how quickly can they sign approvals
• Is your data on offset well performance, geology, and mud programs accessible in a format we can use during planning Options: Fully documented and shared, Partially available, Not available, Available but needs cleansing
• If a required permit arrived two weeks late, would you proceed with the planned mobilization, delay, switch pads, or cancel Options: Proceed as planned, Delay mobilization, Switch to a different pad, Cancel the mobilization

Next steps that shorten the path to spud

• If the first two wells meet your target days to spud and TRIR, what stops you from executing the remainder of the program with the same contractor immediately
• Which of these documents or confirmations would shorten your sign-to-mobilization timeline Options: Signed dayrate or footage agreement, Approved safety plan and KPIs, Formal rig technical confirmation, Proof of insurance and bonds, Mobilization window confirmation
• What internal stakeholders need to be aligned before you can commit, and who is the clearest blocker right now
• How quickly can you make a pilot acceptance decision after observing initial performance, and who has signature authority for a pilot-to-program commitment Options: Within 48 hours, Within 1 week, Within 2-4 weeks, Longer or requires board/JV approval
• If a short pilot proves the performance numbers you need, what would it take for you to sign a multi-well commitment that same week

• Operational Scenarios Solution Session

• Confirm the current state and its cost
• You confirm the demonstrated scenario addresses the exact operational uncertainty that blocks approval of rig commitments.
• Produce scenario analysis for up to two nominated offset wells showing predicted cycle times, expected NPT exposure in hours, walk and mobilization durations, and safety KPI projections, deliver within 7 business days.
• You agree the scenario outputs and KPIs (cycle time, connections/hour, expected NPT hours, TRIR) that will be used to judge readiness.
• Walk a representative drilling scenario
• Provide offset well drilling logs, recent offset performance metrics, and your target AFE timeline for the nominated wells.
• Prove how rig features and crew practices reduce NPT and improve safety
• You commit to providing the offset well data and the decision timeline needed to produce formal scenario deliverables.
• Define the decision criteria and list the stakeholders who will review the scenario deliverable and the target date for approval.
• Validate that this matches your objectives
• Agree next evidence and decision path

• Operational Scenarios Solution Session
• Solution Experience Deck
• Solution Brief - Operational Scenarios

• meeting
• slides
• document

• Rig Mobilization and Site Rig-Up
• Spud and Drill to Target Depth
• Directional and Horizontal Drilling Execution
• Provide Trained Drilling Crew and Shift Coverage
• Automated Pipe Handling Operations
• Connection Time Optimization (Automated Systems)
• Pad-to-Pad Walking Rig Relocation
• Real-Time Rig-State Monitoring and Alerts
• Preventive Maintenance and Onsite Repairs
• Onsite Critical Spares and Consumable Supply
• Casing Running and Cementing Operations
• Wellsite Safety Management and HSE Oversight
• Demobilization and Site Rig-Down

Rig Mobilization and Site Rig-Up

• What rig horsepower class do you require mobilized to the pad (e.g., 1,500 hp or 3,000 hp)? Options: 1,500 hp, 3,000 hp, Either / Flexible, Other (specify)
• Do you have a target spud-ready date tied to an Authorization for Expenditure (AFE) milestone that the mobilization must meet? Options: Yes, provide AFE milestone, No fixed AFE date, Flexible within a 2-week window
• How wide and load-rated is the primary access road and pad surge area for rig transport and pad rig-up (provide width in meters and any axle-load limits)?
• Which permit or third-party approvals must be in place before rig-up (for example local road permits, utility crossing permits, or lease access letters)?
• Describe the expected site services the rig must tie into at rig-up (power distribution panel location, bulk water supply point, pit locations, and fuel delivery access).
• Specify who will provide pad-level temporary works such as cribbing, matting, and crane pads and whether there is an agreed acceptance checklist for pad readiness. Options: You provide pad temporary works, We provide pad temporary works, Shared responsibilities per checklist, Not yet decided

Spud and Drill to Target Depth

• When do you plan to spud relative to lease commitments or AFE schedule (provide exact spud date or range)?
• Who will supply the approved wellbore schematic and final well design (including target total depth, planned casing points, and mud program)? Options: You supply final well design, We accept your template and adapt, Jointly prepared
• Provide the target measured depth (MD) and total depth (TD) for the well and any intermediate casing shoe depths that will affect drilling time.
• Identify the primary formation(s) and expected hole sections where bit runs historically show performance variation (reference offset well names or API well numbers if available).
• Estimate an expected days-on-well to target depth based on offset well performance (provide days or range). Options: Less than 7 days, 7-14 days, 15-30 days, More than 30 days, Provide custom estimate
• What are the measurable acceptance criteria for the drilling phase handover at target depth (for example mud weight within tolerance, directional tolerance, and zero lost-circulation events)?

Directional and Horizontal Drilling Execution

• Which steerable motor or rotary steerable system performance metrics are critical for this program (dogleg severity tolerance, build-rate targets, or average bit lateral footage per day)?
• Do you require control of wellbore azimuth and inclination to specified tolerances at casing points (provide angular tolerance in degrees per 100 ft)? Options: Yes, tighter than 2°/100 ft, Yes, 2–4°/100 ft, No tight control required
• Provide your expected horizontal section length and desired lateral landing zone coordinates or measured depths.
• Identify any formation instability or hole-cleaning challenges experienced on offset laterals that the crew must mitigate (for example sloughing shale or high torque events).
• Specify the target footage-per-day or stage-time metric for horizontal drilling that will be used to evaluate performance. Options: Top-quartile feet/day per offset, Operator target provided, No specific footage target
• Describe any specialized BHA (bottomhole assembly) or BHA integration checks we must perform before running high-angle or extended-reach assemblies.

Provide Trained Drilling Crew and Shift Coverage

• How many crew members per shift do you require on the rig floor and in rig supervision (provide counts for driller, derrickhand, motorman, and rig manager)?
• Do you require crew certification evidence such as competency cards, training matrix, or competency matrix for automated drilling systems? Options: Yes, provide crew competency cards, No formal evidence required, Partial evidence acceptable
• Which shift rotation model do you prefer (for example 14 days on 14 days off, 7x7, or custom rotation)? Options: 14 on / 14 off, 7 on / 7 off, 12-hour daily shifts, Custom rotation
• Identify acceptable crewing contingency levels for sickness or turnover (for example single spare crew per rig or full swing crew available). Options: Single spare per role, Full swing crew available, On-call regional pool, No contingency required
• Provide expected crew language competencies and any site-specific inductions or credentialing required for local regulatory compliance.
• Specify how you will validate crew handover between shifts (for example shift log, electronic handover checklist, or supervisor sign-off). Options: Electronic handover checklist, Paper shift log, Supervisor sign-off only, Other

Automated Pipe Handling Operations

• Which automated pipe-handling system capabilities must be supported at the wellsite (tongs automation, elevator automation, or single-operator stands handling)? Options: Tongs automation, Elevator automation, Single-operator stands handling, Full automation suite required
• Do you have specifications for tubular handling (pipe lengths, weight per foot, connections per stand) that affect automated handler configuration?
• Provide the makeup torque and connection type ranges we must support with automated equipment (for example API 5CT casing coupling torque ranges).
• Identify any site constraints that limit automated equipment footprint (pad setback, reserve pit location, or nearby infrastructure).
• Specify acceptance criteria for automated pipe handling safety interlocks and emergency-stop tests at rig-up.
• Which integration checks with the rig control system and top drive must be completed prior to first-run automated stands?

Connection Time Optimization (Automated Systems)

• What connection-time targets do you expect from automated connections compared with your offset baseline (seconds per connection or percentage improvement)?
• Do you require connection-time telemetry to be reported into your operations dashboard or the rig-state monitoring feed? Options: Yes, into operator dashboard, Yes, into shared platform, No, internal reporting only
• Provide the permitted tolerance for automated connection failures or retries per shift before manual intervention is mandated. Options: Zero retries allowed, Up to 2 retries per shift, Up to 5 retries per shift, Custom threshold
• Identify any proprietary or third-party connection devices on your tubulars that require special handling or adapter tooling.
• Specify the required training or accreditation for personnel overseeing automated connection sequences on your wells. Options: Operator-approved training completed, Standard competency card, Joint training session required
• Indicate how you will accept connection-time performance (for example average seconds/connection over the first 30 stands).

Pad-to-Pad Walking Rig Relocation

• How many pad-to-pad walks are expected in the program and what is the typical pad separation distance in meters or feet?
• Which walking-clearance constraints must we respect (overhead powerlines, fences, or ROWs) and do you have cleared walking corridors on record? Options: Walking corridor cleared, Corridor needs clearing, Not sure / need survey
• Provide the maximum acceptable downtime for a walking move (hours) that will be included in site acceptance criteria. Options: Under 4 hours, 4–12 hours, 12–24 hours, As scheduled / flexible
• Identify any pad preparation or matting you require before a walk (for example temporary cribbing or pre-laid walking rails).
• What are the measurable acceptance criteria for completion of a walking relocation (for example rig leveled within X mm, all systems operational within Y hours)?
• Specify who will coordinate local traffic management and utility isolation during walking operations. Options: You coordinate, We coordinate, Joint coordination

Real-Time Rig-State Monitoring and Alerts

• Which rig-state parameters must be streamed in real time to the shared channel (for example hookload, rotary rpm, torque, pump rate, and mud pit volumes)? Options: Hookload, Rotary rpm, Torque, Pump rate, Mud pit volumes, All of the above
• Do you require alert thresholds for critical events such as high torque, low pump rate, or excessive vibration, and should these integrate with your incident management system? Options: Yes, integrate with incident system, Yes, but alerts to shared channel only, No real-time alerts required
• Provide your preferred data transmission cadence (seconds between telemetry points) and any bandwidth constraints at the pad. Options: 1s, 5s, 10s, 30s, Other
• Identify the retention period for recorded rig-state logs you require for post-run analysis (days or months). Options: 30 days, 90 days, 1 year, Custom
• Specify any cybersecurity or VPN requirements for connecting rig telemetry to your operations center or integration endpoint.
• Which party will own the alert escalation path for real-time safety-critical alarms (for example high-pressure events or loss of well control)? Options: You own escalation, We own escalation, Shared ownership with named roles

Preventive Maintenance and Onsite Repairs

• How often do you require preventive maintenance (PM) windows during the campaign (weekly, biweekly, monthly)? Options: Weekly, Biweekly, Monthly, On-demand
• Do you require PM reports to follow a specific format such as a checklist tied to API (American Petroleum Institute) equipment standards? Options: API-based checklist, Operator template, Standard PM report
• Provide the maximum allowable non-productive time (NPT) per repair event before escalation to senior technical support is required (hours). Options: Under 4 hours, 4–12 hours, Over 12 hours
• Identify onsite repair capabilities required (hydraulic repairs, electrical drive repairs, top drive rebuild) and which require third-party vendor attendance.
• Specify acceptance criteria for completion of a critical repair (for example returned to full operational status and passing functional tests).
• Detail any hours-of-service restrictions or local contractor permit windows that affect when repairs can occur.

Onsite Critical Spares and Consumable Supply

• Which critical spare parts must be stocked onsite at mobilization (top drive spare, draw-works brake parts, pump seals, PLC spare cards)?
• Do you require kit-level inventory reporting with minimum stock levels for consumables (drill pipe protectors, slips, bits)? Options: Yes, kit-level reporting, No, replenish on request, Partial reporting
• Provide lead times you will accept for resupply of critical spares if a part is consumed on location (hours or days). Options: Under 24 hours, 24–72 hours, 3–7 days, Longer
• Identify who will own procurement of long-lead items such as a replacement top drive or SCR (silicon controlled rectifier) drive modules. Options: You procure, We procure, Joint procure
• Specify any consumable brand or specification requirements (for example API-specification cement, specific bit manufacturer part families).
• Estimate typical monthly consumable burn rates we should plan for (drill pipe protectors per month, mud additives per well).

• Master Services Agreement (MSA)
• Statement of Work (SOW)
• Pricing Schedule & Commercial Term Sheet
• Performance & Incentive Addendum
• Mobilization Readiness Confirmation / Notice to Proceed
• HSE & Regulatory Compliance Addendum
• Insurance, Indemnity & Bonds
• Payment Security & Credit Terms
• Change Order Agreement
• Termination & Suspension Terms
• Execution & E-Signature Package

• Go-live Health Check (weeks 1-4)
• First Operational Measurement (weeks 4-10)
• Acceptance Gate — Operational Acceptance (around day 90)
• Monthly Operational and HSE Review
• Quarterly Executive Operational Review

• Update the shared HSE and operations dashboard with this month's TRIR, NPT hours per well, and schedule variance.
• Document root-cause analyses for each metric gap and list remediation tasks with target dates.
• Update the shared issue log with prioritized corrective actions and expected completion dates.
• Restate numeric acceptance criteria from Rig Scope & Responsibilities
• Produce a documented acceptance decision against each numeric criterion recorded in Rig Scope & Responsibilities, captured by the buyer operations signatory.
• If any criterion is conditional or failed, agree a remediation plan with dates sufficient to close the gate within the agreed window.
• Publish the formal acceptance record with pass/fail status for each criterion and the buyer operations signatory's statement.
• Execute the incumbent wind-down checklist and publish confirmation of archived data or retained-read-only status.
• Track all remediation items in the shared tracker with resolution dates and verification steps.
• TRIR and HSE incident summary
• Confirm TRIR and NPT hours per well remain within acceptable trajectory toward targets recorded in Rig Scope & Responsibilities.
• Close or re-prioritize the top open operational issues and confirm next-step owners and dates.
• Re-confirm acceptance criteria and owners
• Close top-priority remediation actions or move them to an agreed escalation path with target completion dates.
• If TRIR exceeds the threshold, schedule a focused HSE detailed review and publish its scope within 48 hours.
• Agree the top 3 operational mitigation priorities for the next quarter with clear resolution timelines.
• Executive summary of AFE schedule variance and recovery plan
• Confirm whether AFE schedule variance and TRIR are acceptable to executive stakeholders and identify any required executive actions.
• Produce and distribute the quarterly operational summary including AFE schedule variance, TRIR trend, NPT hours, and estimated cost impact.
• Document the top 3 mitigation priorities with target dates and verification criteria.
• Update the executive risk register with mitigation owners and report back on progress at the next monthly review.
• Confirm the rig is mobilized and reporting channels are live.
• Produce a prioritized list of open issues with assigned owners and target remediation dates.
• Publish a one-page mobilization health summary and distribute to the shared channel.
• Log all critical blockers in the shared issue tracker and set target resolution dates.
• Provide an operations contact list and escalation path to the buyer's team.
• Present first data for TRIR and NPT hours per well
• Establish whether TRIR and NPT hours per well are trending toward the numeric targets recorded in Rig Scope & Responsibilities.
• Agree corrective actions for any metric gaps and confirm a timeline to the Acceptance Gate.
• Publish the metric dashboards (TRIR, NPT hours per well, AFE schedule variance) with source data and definitions.
• Deployment and mobilization validation
• Present outcome data against each criterion
• Present AFE schedule variance
• Quarterly TRIR and safety trend review
• NPT events and root-cause review
• AFE schedule adherence and forecast
• Diagnose root causes for any gaps
• Document pass/fail and capture formal acceptance decision
• Early adoption signals and crew readiness
• NPT cumulative hours and cost impact
• Agree corrective actions, owners, and dates
• Agree remediation plan for any failed or conditional items
• Open issue burn-down and continuous improvement items
• Crew performance and retention indicators
• Open issues and immediate blockers
• Agree immediate remediation actions
• Confirm incumbent contractor wind-down or retention status
• Top risks and agreed mitigation priorities for the next quarter
• Confirm timeline to Acceptance Gate
• Escalations and barrier checks